Increasing the recovery of hydrocarbons from existing reservoirs is a continuing challenge. Although a myriad of techniques exist for enhancing the recovery of hydrocarbons, some conventional methods for enhancing the recovery of hydrocarbons include steam flooding and water flooding, also known as enhanced oil recovery (EOR) methods.
These conventional methods often involve injection of steam or water into a secondary injection well to provide a motive force to push remaining hydrocarbon reserves in the formation towards the production well. In this way, these secondary operations assist in the recovery of hydrocarbons that may have otherwise remained in the formation. Where a water flood is desired, operators typically employ naturally occurring brine water as to the motive driver.
Another enhanced oil recovery method relies on carbon dioxide injection. It has been discovered that the addition of carbon dioxide (CO2) to a formation assists in enhancing recovery of hydrocarbons by a variety of mechanisms. For example, carbon dioxide has the beneficial effect of reducing the viscosity of the hydrocarbons, allowing for more efficient flow of the hydrocarbons through the formation. Because of the low viscosity of carbon dioxide, however, a phenomenon, known as viscous fingering, often occurs where the carbon dioxide forms circuitous channels and bypasses portions of the formation due to heterogeneities of the formation and the differing viscosity of the carbon dioxide as compared to the formation fluids. This viscous fingering often reduces the efficiency of carbon dioxide injection as an enhanced oil recovery method to a point of infeasibility. In this way, it is well known that the low viscosity of carbon dioxide and hence its high mobility in oil reservoirs adversely affects the sweep efficiency during carbon dioxide injection.
To overcome this bypassing problem, operators have employed various injection strategies including carbonated brine injection (e.g. introducing carbon dioxide into naturally occurring brines, which are then used as an enhanced treatment fluid). Naturally occurring brines however are known to have a high salinity. The solubility of carbon dioxide in naturally occurring brines, however, is greatly limited due to the high salinity of the brine water commonly used. To obtain a significant improvement in oil recovery, the amount of carbon dioxide (liquid or dense-gas) available in the brine must exceed a certain minimum. Thus, the limited dissolvability of carbon dioxide in high salinity brines adversely affects the enhancement potential of the high salinity carbonated brine. As a result, carbonated brine injection projects are generally not successful because of an insufficient transfer of carbon dioxide from water to oil due to the low carbon dioxide content of the high salinity brine. Indeed, this low carbon dioxide content is further magnified by the problem that minerals in the formation often consume injected carbon dioxide such that the injected carbon dioxide is unavailable for enhancement of hydrocarbon recovery.
Accordingly, conventional methods of using high salinity carbonated brines in secondary operations suffer from the disadvantage of being limited in their carbon dioxide content, which adversely affect the ability of the high salinity carbonated brine to enhance recovery of hydrocarbons.